Production of heavy oil and bitumen from a subsurface reservoir can be quite challenging. Initial viscosity of the oil at reservoir temperature is often greater than a million centipoise (cP). Because of this high viscosity oil cannot be pumped out of the ground using typical methods, and it often must be mined or processed in situ. Surface mining is limited to reservoirs to a depth of about 70 meters. Greater depths are not economical to access and most reserves are not accessible by the method. Since only a relatively small percentage of bitumen and oil sand deposits (such as the Athabasca oils sands of Alberta, Canada), are recoverable through open-pit mining, the majority of require some form of in situ extraction.
Steam-assisted gravity drainage (SAGD) is an in situ processing method first introduced by Roger Butler in 1973 as a means of producing heavy oil and bitumen. SAGD uses two parallel and superposed horizontal wells that are vertically separated by about 5 meters (See FIG. 1). First, steam is circulated in both wells to conductively heat the petroleum deposit between the well pair. The mobile petroleum is then gravity drained to the lower horizontal well. During drainage, steam is injected into the top horizontal well (injection well) and oil and condensate are produced from the lower horizontal well (production well).
As an in situ recovery process, SAGD requires on-site steam generation and water treatment, translating into expensive surface facilities. Since steam-to-oil ratios are high and natural gas is often used to generate steam, SAGD is expensive to operate. SAGD is very energy intensive largely because the reservoir rock and fluids must be heated enough to lower viscosity and mobilize the petroleum, and heat is lost to overburden and underburden, water and gas intervals above, below, and within the main pay section, and to the non-productive rock in the reservoir.
On average, a third of the energy is produced back with fluids in the reservoir, a third is lost to overburden and underburden, and a third is left behind in the reservoir after abandonment. The inefficiency results in a steam-to-oil ratio (SOR) of 3.0 (vol/vol), and a 50-60% recovery factor of the original bitumen. According to the Canadian National Energy Board, 34 m3 of natural gas is needed to produce one barrel of bitumen from in situ projects, and about 20 m3 for integrated projects. Nonetheless, since a barrel of oil equivalent (BOE) is about 170 m3 of gas, this process still represents a large gain in energy. To compound these issues, however, heavy oil and bitumen are sold at significant discounts compared to oil product benchmarks, such as Western Texas Intermediate (WTI), providing an exceedingly challenging economic environment.
Attempts have been made to address the limitations of SAGD, for example, by co-injecting steam with non-condensable gases (NCGs), such as CO2, flue or combustion gases, and light hydrocarbons. The NCG provides an insulating layer at the top of the steam chamber, resulting in higher thermal efficiency. Co-injection decreases the amount of steam needed to recover petroleum from a formation, thereby decreasing the steam-to-oil ratio. The NCG also increases pressure in the reservoir, promoting drainage of produced liquid to the production well.
Co-injection, however, has its own limitations. NCG breakthrough at the SAGD production well and reflux of the gas in the steam chamber suppress the rate of oil production. NCG breakthrough decreases the relative permeability of oil, thus limiting production (FIGS. 2 & 3). Gas reflux from draining fluids occurs close to the injection well region. Because of partial pressure effects of NCG, temperatures are lowered at the drainage interface, reducing the rate of oil production (FIG. 4). Slight changes in temperature can substantially affect solubility of NCG or light hydrocarbons, promoting reflux of co-injected fluids back into the steam chamber. These gases also tend to move towards the production well, increasing gas saturation and decreasing oil permeability near the production well. All these complications can diminish performance, delay production, and increase cost.
U.S. Pat. No. 4,008,764 describes a method for recovering viscous petroleum from a formation that has been penetrated by at least one production well and by at least one injection well, both wells being in fluid communication with the formation, comprising, among other things, introducing a gaseous mixture of carrier gas and solvent into a formation via the injection well, and recovering a produced fluid comprising formation petroleum. The inert carrier gas, for example N2, air, ethylene, propylene, CO2, H2S, H2, and/or anhydrous ammonia (NH3), is gaseous at formation temperature and pressure. The solvent, for example paraffinic hydrocarbons and/or carbon disulfide (CS2), is liquid at formation temperature and pressure. U.S. Pat. No. 4,008,764 fails to describe use of steam in the gaseous mixture.
U.S. Pat. No. 74,644,756 describes a method for recovering heavy hydrocarbons from an underground reservoir that has been penetrated by an injection well and a production well, comprising, among other things, injecting steam and a heavy hydrocarbon solvent into the injection well over time while producing reservoir hydrocarbons from the production well, and transitioning from steam and heavy hydrocarbon solvent injection to a lighter hydrocarbon solvent injection while continuing to produce hydrocarbons from the production well. U.S. Pat. No. 74,644,736 fails to describe use of NCG in a gaseous mixture or using more than one injection well.
U.S. Pat. No. 7,527,096 describes a method for extracting hydrocarbons from a reservoir, comprising, among other things, continuously injecting a solvent fluid into the reservoir through a first injection well, continually producing reservoir fluid from a second production well, and upon solvent fluid breakthrough at the second well, switching the roles of the two wells, such that the injection well becomes the production well, and vice versa. The solvent fluid can comprise steam, methane, butane, ethane, propane, pentanes, hexanes, heptanes, CO2 and mixtures thereof. At least two horizontal wells can be disposed in the reservoir and perform injection or production functions simultaneously. U.S. Pat. No. 7,527,096 fails to describe the disposition of injection wells and production wells relative to each other.
US20080017372 describes a method for recovering heavy hydrocarbons from an underground reservoir containing heavy hydrocarbons, an injection well and a production well, comprising: injecting steam into the reservoir to form a steam vapor chamber; co-injecting predetermined quantities of NCG, hydrocarbon solvent and steam into the steam vapor chamber to maximize solubility of the solvent in the heavy hydrocarbons; recovering produced hydrocarbons within the production well; controlling the volume of the steam vapor chamber by progressively adjusting the volume of steam, NCG and hydrocarbon solvent injected into the reservoir, whereby the hydrocarbon solvent and NCG are predominant relative to the volume of steam, and recovering further produced heavy hydrocarbons. US20080017372 fails to describe two injection wells and their disposition relative to each other and to the production well. The application also states that it remains unclear what the optimal amount NCG is relative to injected steam.
What is lacking is a method to increase the efficiency of SAGD without introducing new problems, such as solvent reflux, gas breakthrough, delayed production, and the like.